Desulfurization with octane enhancement

ABSTRACT

A desulfurization system employing a system of fluidizable and circulatable solid particles to desulfurize a hydrocarbon-containing fluid in a fluidized bed reactor. The solid particulate system includes solid sorbent particles operable to remove sulfur from the hydrocarbon-containing fluid stream and solid catalyst particles operable to enhance the octane of the resulting desulfurized hydrocarbon-containing fluid stream. The solid particulate system can be circulated between a reactor, regenerator, and reducer, to thereby allow for substantially continuous desulfurization in the reactor.

BACKGROUND OF THE INVENTION

This invention relates generally to systems for desulfurizinghydrocarbon-containing fluid streams such as cracked gasoline and dieselfuel. In another aspect, the invention concerns compositions that can beused to remove sulfur from hydrocarbon-containing fluid streams withminimal octane loss, or even octane enhancement.

Hydrocarbon-containing fluids such as gasoline and diesel fuelstypically contain a quantity of sulfur. High levels of sulfur in suchautomotive fuels are undesirable because oxides of sulfur present inautomotive exhaust may irreversibly poison noble metal catalystsemployed in automobile catalytic converters. Emissions from suchpoisoned catalytic converters may contain high levels of non-combustedhydrocarbons, oxides of nitrogen, and/or carbon monoxide, which, whencatalyzed by sunlight, form ground level ozone, more commonly referredto as smog.

Much of the sulfur present in the final blend of most gasolinesoriginates from a gasoline blending component commonly known as“cracked-gasoline.” Thus, reduction of sulfur levels in cracked-gasolinewill inherently serve to reduce sulfur levels in most gasolines, suchas, automobile gasolines, racing gasolines, aviation gasolines, boatgasolines, and the like. Many conventional processes exist for removingsulfur from cracked-gasoline. However, most conventional sulfur removalprocesses, such as hydrodesulfurization, tend to saturate olefins andaromatics in the cracked-gasoline and thereby reduce its octane number(both research and motor octane number). Thus, there is a need for aprocess wherein desulfurization of cracked-gasoline is achieved whilethe octane number is maintained or even enhanced.

SUMMARY OF THE INVENTION

Accordingly, it is an object of the present invention to provide a novelprocess for removing sulfur from a hydrocarbon-containing fluid streamwhile minimizing octane loss or even enhancing the octane of theresulting desulfurized fluid stream.

A further object of the present invention is to provide a novel solidparticulate system which can be employed in fluidized bed reactors andreadily circulated between various vessels without significant attritionof the particles.

A still further object of the present invention is to provide ahydrocarbon desulfurization system which minimizes hydrogen consumptionwhile providing improved sulfur removal and enhanced octane.

It should be noted that the above-listed objects need not all beaccomplished by the invention claimed herein and other objects andadvantages of the invention will be apparent from the followingdescription of the preferred embodiments and appended claims.

Accordingly, in one embodiment of the present invention, there isprovided a desulfurization process comprising the steps of: (a)contacting a solid particulate system with a hydrocarbon-containingfluid stream in a desulfurization zone under desulfurization conditions,wherein said solid particulate system comprises a sorbent and acatalyst, wherein said sorbent is capable of removing sulfur from thehydrocarbon-containing fluid stream at the desulfurization conditions,wherein said catalyst is capable of increasing the octane of thehydrocarbon-containing fluid stream at the desulfurization conditions;(b) contacting said solid particulate system with an oxygen-containingregeneration stream in a regeneration zone under regenerationconditions; and (c) contacting said solid particulate system with ahydrogen-containing reducing stream in a reducing zone under reducingconditions.

In another embodiment of the present invention, there is provided adesulfurization process comprising the steps of: (a) contacting a firstportion of a solid particulate system with a hydrocarbon-containingfluid stream in a first fluidized bed reactor under desulfurizationconditions sufficient to remove sulfur from said hydrocarbon-containingfluid stream, wherein said solid particulate system comprises aplurality of individual sorbent particles and a plurality of individualcatalyst particles, wherein each of said sorbent particles compriseszinc oxide and a promoter metal component, wherein each of said catalystparticles comprises a zeolite capable of isomerization and cracking atleast some of the components in the hydrocarbon-containing fluid streamat said desulfurization conditions, wherein the weight ratio of saidsorbent particles to said catalyst particles is in the range of fromabout 100:1 to about 4:1; and (b) simultaneously with step (a),contacting a second portion of the solid particulate system with anoxygen-containing regeneration stream in a second fluidized bed reactorunder regeneration conditions sufficient to remove coke from saidcatalyst particles and remove sulfur from said sorbent particles.

In a further embodiment of the present invention, there is provided asolid particulate system comprising an unbound mixture of sorbentparticles and catalyst particles. The sorbent particles comprise zincoxide and a promoter metal component. The catalyst particles comprise azeolite having a largest ring with at least 10 T-atoms. The weight ratioof the sorbent particles to the catalyst particles is in the range offrom about 100:1 to about 4:1. The mean particle sizes of the sorbentparticles and the catalyst particles are both in the range of from about20 to about 200 microns.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic process flow diagram of a desulfurization unitconstructed in accordance with the principals of the present invention,particularly illustrating the circulation of a regenerable solidparticulate system through the reactor, regenerator, and reducer.

FIG. 2 is a schematic process flow diagram of a pilot plant used toperform desulfurization tests summarized in the EXAMPLES section, below.

FIG. 3 is a graph plotting change in road octane versus weight percentof catalyst additive for desulfurization tests summarized in theEXAMPLES section.

FIG. 4 is a graph plotting volume percent retained versus weight percentof catalyst additive for desulfurization tests summarized in theEXAMPLES section.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring initially to FIG. 1, a desulfurization unit 10 is illustratedas generally comprising a fluidized bed reactor 12, a fluidized bedregenerator 14, and a fluidized bed reducer 16. A system of finelydivided solid particles is circulated in desulfurization unit 10 toprovide for substantially continuous sulfur removal (in reactor 12) froma sulfur-containing hydrocarbon, such as cracked-gasoline or dieselfuel. The finely divided solid particulate system employed indesulfurization unit 10 preferably comprises an unbound mixture of aplurality of individual sorbent particles and a plurality of individualcatalyst particles. Although it is within the ambit of one embodiment ofthe present invention for the sorbent and catalyst to be bound togetherin the same particle, it is preferred for the sorbent particles and thecatalyst particles to be discrete solid particles that can move freelyrelative to one another. Preferably, the weight ratio of the sorbentparticles to the catalyst particles in the solid particulate system isin the range of from about 100:1 to about 4:1, more preferably of fromabout 40:1 to about 5:1, and most preferably from 20:1 to 10:1.

The solid catalyst particles of the solid particulate system employed indesulfurization unit 10 can be any sufficiently fluidizable,circulatable, and regenerable solid acid catalyst having sufficientisomerization activity, cracking activity, attrition resistance, andcoke resistance at the operating conditions of desulfurization unit 10.The catalyst particles are preferably more acidic than about −1 on theHammett scale, more preferably the catalyst particles are more acidicthan about −3 on the Hammett scale, and most preferably the catalystparticles are more acidic than −6 on the Hammett scale. The catalystparticles preferably comprise a zeolite in an amount in the range offrom about 5 to about 50 weight percent, with the balance being aconventional binder system such as clay (e.g., kaolin clay) or a mixtureof clay and a binding alumina. Most preferably, the catalyst particlescomprise the zeolite in an amount in the range of from 10 to 30 weightpercent. It is preferred for the largest ring of the zeolite employed inthe catalyst particles of the present invention to have at least 8T-atoms. More preferably, the largest ring of the zeolite has at least10 T-atoms, still more preferably the largest ring of the zeolite has 10to 12 T-atoms, and most preferably the largest ring of the zeolite has10 T-atoms.

It is further preferred for the zeolite to have a channel dimensionalityof 3. It is preferred for the zeolite employed in the solid particulatesystem of the present invention to have a framework type code selectedfrom the group consisting of AEL, AET, AFI, AFO, AFR, AFS, AFY, AHT,ASV, ATO, ATS, BEA, BEC, BOG, BPH, CAN, CFI, CGF, CGS, CLO, CON, CZP,DAC, DFO, DON, EMT, EPI, EUO, FAU, FER, GME, GON, HEU, IFR, ISV, LAU,LTL, MAZ, MEI, MEL, MFI, MFS, MOR, MTT, MTW, MWW, NES, OFF, OSI, OSO,PAR, RON, SAO, SBE, SBS, SBT, SFE, SFF, SFG, STF, STI, TER, TON, VET,VFI, WEI, and WEN. More preferably, the zeolite has a framework typecode selected from the group consisting of AFS, AFY, BEA, BEC, BHP, CGS,CLO, CON, DFO, EMT, FAU, GME, ISV, MEI, MEL, MFI, SAO, SBS, SBT, andWEN. Still more preferably the zeolite has a MFI framework type code.The above-listed framework type codes follow the rules set up by anIUPAC Commission on Zeolite Nomenclature in 1978, as outlined in R. M.Barrer, “Chemical Nomenclature and Formulation of Compositions ofSynthetic and Natural Zeolites”, Pure Appl. Chem. 51, 1091(1979).Further information on framework type codes is available in Ch.Baerlocher, W. M. Meier, D. H. Olson, Atlas of Zeolite Framework Types,5th ed., Elsevier, Amsterdam (2001), the entire disclosure of which ishereby incorporated by reference. Most preferably, the zeolite of thecatalyst particles is ZSM-5 that has been ion exchanged and calcined sothat it exists in its hydrogen form (i.e., H-ZSM-5).

It is also preferred that the zeolite have a high silica (SiO₂) toalumina (Al₂O₃) molar ratio. Usually the zeolite silica to alumina molarratio will be within a range of about 10 to about 10,000 and preferably,within a ratio of about 15 to about 5,000. Most preferably, for bestoctane enhancement, the silica to alumina molar ratio will be within arange of 20 to 1000.

The solid sorbent particles of the solid particulate system employed indesulfurization unit 10 can be any sufficiently fluidizable,circulatable, and regenerable zinc oxide-based composition havingsufficient desulfurization activity and sufficient attrition resistanceat the conditions in desulfurization unit 10. A description of such asorbent composition is provided in U.S. Pat. No. 6,429,170 and U.S.patent application Ser. No. 10/072,209, the entire disclosures of whichare incorporated herein by reference.

In fluidized bed reactor 12, a hydrocarbon-containing fluid stream ispassed upwardly through a fluidized bed of the solid particulate systemso that the reduced solid sorbent and catalyst particles present inreactor 12 are contacted with the fluid stream. The reduced solidsorbent particles contacted with the hydrocarbon-containing stream inreactor 12 preferably initially (i.e., immediately prior to contactingwith the hydrocarbon-containing fluid stream) comprise zinc oxide and areduced-valence promoter metal component. Though not wishing to be boundby theory, it is believed that the reduced-valence promoter metalcomponent of the reduced solid sorbent particles facilitates the removalof sulfur from the hydrocarbon-containing stream, while the zinc oxideoperates as a sulfur storage mechanism via its conversion to zincsulfide.

The reduced-valence promoter metal component of the reduced solidsorbent particles preferably comprises a promoter metal selected from agroup consisting of nickel, cobalt, iron, manganese, tungsten, silver,gold, copper, platinum, zinc, tin, ruthenium, molybdenum, antimony,vanadium, iridium, chromium, palladium. More preferably, thereduced-valence promoter metal component comprises nickel as thepromoter metal. As used herein, the term “reduced-valence” whendescribing the promoter metal component, shall denote a promoter metalcomponent having a valence which is less than the valence of thepromoter metal component in its common oxidized state. Morespecifically, the reduced solid sorbent particles employed in reactor 12should include a promoter metal component having a valence which is lessthan the valence of the promoter metal component of the regenerated(i.e., oxidized) solid sorbent particulates exiting regenerator 14. Mostpreferably, substantially all of the promoter metal component of thereduced solid sorbent particulates has a valence of zero.

In a preferred embodiment of the present invention, the reduced-valencepromoter metal component comprises, consists of, or consists essentiallyof, a substitutional solid metal solution characterized by the formula:M_(A)Zn_(B), wherein M is the promoter metal and A and B are eachnumerical values in the range of from 0.01 to 0.99. In the above formulafor the substitutional solid metal solution, it is preferred for A to bein the range of from about 0.70 to about 0.97, and most preferably inthe range of from about 0.85 to about 0.95. It is further preferred forB to be in the range of from about 0.03 to about 0.30, and mostpreferably in the range of from about 0.05 to 0.15. Preferably, B isequal to (1−A).

Substitutional solid solutions have unique physical and chemicalproperties that are important to the chemistry of the sorbentcomposition described herein. Substitutional solid solutions are asubset of alloys that are formed by the direct substitution of thesolute metal for the solvent metal atoms in the crystal structure. Forexample, it is believed that the substitutional solid metal solution(M_(A)Zn_(B)) found in the reduced solid sorbent particles is formed bythe solute zinc metal atoms substituting for the solvent promoter metalatoms. There are three basic criteria that favor the formation ofsubstitutional solid solutions: (1) the atomic radii of the two elementsare within 15 percent of each other; (2) the crystal structures of thetwo pure phases are the same; and (3) the electronegativities of the twocomponents are similar. The promoter metal (as the elemental metal ormetal oxide) and zinc oxide employed in the solid sorbent particlesdescribed herein preferably meet at least two of the three criteria setforth above. For example, when the promoter metal is nickel, the firstand third criteria, are met, but the second is not. The nickel and zincmetal atomic radii are within 10 percent of each other and theelectronegativities are similar. However, nickel oxide (NiO)preferentially forms a cubic crystal structure, while zinc oxide (ZnO)prefers a hexagonal crystal structure. A nickel zinc solid solutionretains the cubic structure of the nickel oxide. Forcing the zinc oxideto reside in the cubic structure increases the energy of the phase,which limits the amount of zinc that can be dissolved in the nickeloxide structure. This stoichiometry control manifests itselfmicroscopically in a 92:8 nickel zinc solid solution(Ni_(0.92)Zn_(0.08)) that is formed during reduction and microscopicallyin the repeated regenerability of the solid sorbent particles.

In addition to zinc oxide and the reduced-valence promoter metalcomponent, the reduced solid sorbent particles employed in reactor 12may further comprise a porosity enhancer and an aluminate. The aluminateis preferably a promoter metal-zinc aluminate substitutional solidsolution. The promoter metal-zinc aluminate substitutional solidsolution can be characterized by the formula: M_(Z)Zn_((1−Z))Al₂O₄,wherein Z is a numerical value in the range of from 0.01 to 0.99. Theporosity enhancer, when employed, can be any compound which ultimatelyincreases the macroporosity of the solid sorbent particles. Preferably,the porosity enhancer is perlite. The term “perlite” as used herein isthe petrographic term for a siliceous volcanic rock which naturallyoccurs in certain regions throughout the world. The distinguishingfeature, which sets it apart from other volcanic minerals, is itsability to expand four to twenty times its original volume when heatedto certain temperatures. When heated above 1600° F., crushed perliteexpands due to the presence of combined water with the crude perliterock. The combined water vaporizes during the heating process andcreates countless tiny bubbles in the heat softened glassy particles. Itis these diminutive glass sealed bubbles which account for its lightweight. Expanded perlite can be manufactured to weigh as little as 2.5lbs per cubic foot. Typical chemical analysis properties of expandedperlite are: silicon dioxide 73%, aluminum oxide 17%, potassium oxide5%, sodium oxide 3%, calcium oxide 1%, plus trace elements. Typicalphysical properties of expanded perlite are: softening point1,600–2,000° F., fusion point 2,300° F.–2,450° F., pH 6.6–6.8, andspecific gravity 2.2–2.4. The term “expanded perlite” as used hereinrefers to the spherical form of perlite which has been expanded byheating the perlite siliceous volcanic rock to a temperature above1,600° F. The term “particulate expanded perlite” or “milled perlite” asused herein denotes that form of expanded perlite which has beensubjected to crushing so as to form a particulate mass wherein theparticle size of such mass is comprised of at least 97 percent ofparticles having a size of less than two microns. The term “milledexpanded perlite” is intended to mean the product resulting fromsubjecting expanded perlite particles to milling or crushing.

The reduced solid sorbent particles initially contacted with thehydrocarbon-containing fluid stream in reactor 12 can comprise zincoxide, the reduced-valence promoter metal component (M_(A)Zn_(B)), theporosity enhancer (PE), and the promoter metal-zinc aluminate(M_(Z)Zn_((1−Z))Al₂O₄) in the ranges provided below in Table 1.

TABLE 1 Components of the Reduced Solid Sorbent Particulates ZnOM_(A)Zn_(B) PE M_(Z)Zn_((1–z))Al₂O₄ Range (wt %) (wt %) (wt %) (wt %)Preferred  5–80  5–80  2–50  1–50 More Preferred 20–60 20–60  5–30  5–30Most Preferred 30–50 30–40 10–20 10–20

The physical properties of the sorbent and catalyst particles of thesolid particulate system can significantly affect the particulatesystem's suitability for use in desulfurization unit 10. Key physicalproperties of the sorbent and catalyst particles include, for example,particle shape, particle size, particle density, and resistance toattrition. The particles of the solid particulate system (i.e., themixture of sorbent particles and catalyst particles) employed indesulfurization unit 10 preferably comprise substantially microsphericalparticles having a mean particle size in the range of from about 20 toabout 200 microns, more preferably in the range of from about 40 toabout 150 microns, and most preferably in the range of from about 50 toabout 100 microns. As used herein, the term “finely divided” denotesparticles having a mean particle size less than 500 microns.

The average density of the sorbent particles in the solid particulatesystem is preferably in the range of from about 0.5 to about 1.5 gramsper cubic centimeter (g/cc), more preferably in the range of from about0.8 to about 1.3 g/cc, and most preferably in the range of from 0.9 to1.2 g/cc. The average density of the catalyst particles in the solidparticulate system is preferably within about 50 percent of the averagedensity of the sorbent particulates, more preferably within about 25percent of the average density of the sorbent particulates. The particlesize and density of the sorbent and catalyst particles preferablyqualify the particles of the solid particulate system as Group A solidsunder the Geldart group classification system described in PowderTechnol., 7, 285–292 (1973). The sorbent and catalyst particles of thesolid particulate system preferably have high resistance to attrition.As used herein, the term “attrition resistance” denotes a measure of aparticle's resistance to size reduction under controlled conditions ofturbulent motion. The attrition resistance of a particle can bequantified using the jet cup attrition test, similar to the DavisonIndex. The Jet Cup Attrition Index represents the weight percent of theover 44 micrometer particle size fraction which is reduced to particlesizes of less than 37 micrometers under test conditions and involvesscreening a 5 gram sample of solid particles to remove particles in the0 to 44 micrometer size range. The particles above 44 micrometers arethen subjected to a tangential jet of air at a rate of 21 liters perminute introduced through a 0.0625 inch orifice fixed at the bottom of aspecially designed jet cup (1″ I.D.×2″ height) for a period of 1 hour.The Jet Cup Attrition Index (JCAI) is calculated as follows:

${JCAI} = {\frac{{{Wt}.\mspace{14mu}{of}}\mspace{14mu} 0\text{–}37\mspace{14mu}{Micrometer}\mspace{14mu}{Formed}\mspace{14mu}{During}\mspace{14mu}{Test}}{{{{Wt}.\mspace{14mu}{of}}\mspace{14mu}{Original}} + {44\mspace{14mu}{Micrometer}\mspace{14mu}{Fraction}\mspace{14mu}{Being}\mspace{14mu}{Tested}}} \times 100 \times {CF}}$The Correction Factor (CF) (presently 0.30) is determined by using aknown calibration standard to adjust for differences in jet cupdimensions and wear. The sorbent and catalyst particles employed in thepresent invention preferably have a Jet Cup Attrition Index value ofless than about 30, more preferably less than about 20, and mostpreferably less than 15.

The hydrocarbon-containing fluid stream contacted with the solidparticulate system in reactor 12 preferably comprises asulfur-containing hydrocarbon and hydrogen. The molar ratio of thehydrogen to the sulfur-containing hydrocarbon charged to reactor 12 ispreferably in the range of from about 0.1:1 to about 3:1, morepreferably in the range of from about 0.2:1 to about 1:1, and mostpreferably in the range of from 0.4:1 to 0.8:1. Preferably, thesulfur-containing hydrocarbon is a fluid which is normally in a liquidstate at standard temperature and pressure, but which exists in agaseous state when combined with hydrogen, as described above, andexposed to the desulfurization conditions in reactor 12. Thesulfur-containing hydrocarbon preferably can be used as a fuel or aprecursor to fuel. Examples of suitable sulfur-containing hydrocarbonsinclude cracked-gasoline, diesel fuels, jet fuels, straight-run naphtha,straight-run distillates, coker gas oil, coker naphtha, alkylates, andstraight-run gas oil. More preferably, the sulfur-containing hydrocarboncomprises a hydrocarbon fluid selected from the group consisting ofgasoline, cracked-gasoline, diesel fuel, and mixtures thereof. Mostpreferably, the sulfur-containing hydrocarbon is cracked-gasoline.

As used herein, the term “gasoline” denotes a mixture of hydrocarbonsboiling in a range of from about 100° F. to about 400° F., or anyfraction thereof. Examples of suitable gasolines include, but are notlimited to, hydrocarbon streams in refineries such as naphtha,straight-run naphtha, coker naphtha, catalytic gasoline, visbreakernaphtha, alkylates, isomerate, reformate, and the like, and mixturesthereof.

As used herein, the term “cracked-gasoline” denotes a mixture ofhydrocarbons boiling in a range of from about 100° F. to about 400° F.,or any fraction thereof, that are products of either thermal orcatalytic processes that crack larger hydrocarbon molecules into smallermolecules. Examples of suitable thermal processes include, but are notlimited to, coking, thermal cracking, visbreaking, and the like, andcombinations thereof. Examples of suitable catalytic cracking processesinclude, but are not limited to, fluid catalytic cracking, heavy oilcracking, and the like, and combinations thereof. Thus, examples ofsuitable cracked-gasolines include, but are not limited to, cokergasoline, thermally cracked gasoline, visbreaker gasoline, fluidcatalytically cracked gasoline, heavy oil cracked-gasoline and the like,and combinations thereof. In some instances, the cracked-gasoline may befractionated and/or hydrotreated prior to desulfurization when used asthe sulfur-containing fluid in the process in the present invention.

As used herein, the term “diesel fuel” denotes a mixture of hydrocarbonsboiling in a range of from about 300° F. to about 750° F., or anyfraction thereof. Examples of suitable diesel fuels include, but are notlimited to, light cycle oil, kerosene, jet fuel, straight-run diesel,hydrotreated diesel, and the like, and combinations thereof.

The sulfur-containing hydrocarbon described herein as suitable feed inthe inventive desulfurization process comprises a quantity of olefins,aromatics, and sulfur, as well as paraffins and naphthenes. The amountof olefins in gaseous cracked-gasoline is generally in a range of fromabout 10 to about 35 weight percent olefins based on the total weight ofthe gaseous cracked-gasoline. The amount of aromatics in gaseouscracked-gasoline is generally in a range of from about 20 to about 40weight percent aromatics based on the total weight of the gaseouscracked-gasoline. The amount of atomic sulfur in the sulfur-containinghydrocarbon fluid, preferably cracked-gasoline, suitable for use in theinventive desulfurization process is generally greater than about 50parts per million by weight (ppmw) of the sulfur-containing hydrocarbonfluid, more preferably in a range of from about 100 ppmw atomic sulfurto about 10,000 ppmw atomic sulfur, and most preferably from 150 ppmwatomic sulfur to 500 ppmw atomic sulfur. It is preferred for at leastabout 50 weight percent of the atomic sulfur present in thesulfur-containing hydrocarbon fluid employed in the present invention tobe in the form of organosulfur compounds. More preferably, at leastabout 75 weight percent of the atomic sulfur present in thesulfur-containing hydrocarbon fluid is in the form of organosulfurcompounds, and most preferably at least 90 weight percent of the atomicsulfur is in the form of organosulfur compounds. As used herein,“sulfur” used in conjunction with “ppmw sulfur” or the term “atomicsulfur”, denotes the amount of atomic sulfur (about 32 atomic massunits) in the sulfur-containing hydrocarbon, not the atomic mass, orweight, of a sulfur compound, such as an organosulfur compound.

As used herein, the term “sulfur” denotes sulfur in any form normallypresent in a sulfur-containing hydrocarbon such as cracked-gasoline ordiesel fuel. Examples of such sulfur which can be removed from asulfur-containing hydrocarbon fluid through the practice of the presentinvention include, but are not limited to, hydrogen sulfide, carbonalsulfide (COS), carbon disulfide (CS₂), mercaptans (RSH), organicsulfides (R—S—R), organic disulfides (R—S—S—R), thiophene, substitutethiophenes, organic trisulfides, organic tetrasulfides, benzothiophene,alkyl thiophenes, alkyl benzothiophenes, alkyl dibenzothiophenes, andthe like, and combinations thereof, as well as heavier molecular weightsof the same which are normally present in sulfur-containing hydrocarbonsof the types contemplated for use in the desulfurization process of thepresent invention, wherein each R can by an alkyl, cycloalkyl, or arylgroup containing one to 10 carbon atoms.

As used herein, the term “fluid” denotes gas, liquid, vapor, andcombinations thereof.

As used herein, the term “gaseous” denotes the state in which thesulfur-containing hydrocarbon fluid, such as cracked-gasoline or dieselfuel, is primarily in a gas or vapor phase.

In fluidized bed reactor 12, the solid particulate system is contactedwith the upwardly flowing gaseous hydrocarbon-containing fluid streamunder a set of desulfurization conditions sufficient to produce adesulfurized hydrocarbon, sulfur-loaded sorbent particles, and cokedcatalyst particles. The flow of the hydrocarbon-containing fluid streamis sufficient to fluidize the bed of solid particles located in reactor12. The desulfurization conditions in reactor 12 include temperature,pressure, weighted hourly space velocity (WHSV), and superficialvelocity. The preferred ranges for such desulfurization conditions areprovided below in Table 2.

TABLE 2 Desulfurization Conditions Temp. Press. WHSV Superficial Vel.Range (° F.) (psig) (hr⁻¹) (ft/s) Preferred 250–1200  25–750 1–200.25–5   More Preferred 500–1000 100–400 2–12 0.5–2.5 Most Preferred700–850  150–250 3–8  1.0–1.5

When the reduced solid sorbent particles are contacted with thehydrocarbon-containing stream in reactor 12 under desulfurizationconditions, sulfur compounds, particularly organosulfur compounds,present in the hydrocarbon-containing fluid stream are removed from suchfluid stream. At least a portion of the sulfur removed from thehydrocarbon-containing fluid stream is employed to convert at least aportion of the zinc oxide of the reduced solid sorbent particles intozinc sulfide.

In contrast to many conventional sulfur removal processes (e.g.,hydrodesulfurization), it is preferred that substantially none of thesulfur in the sulfur-containing hydrocarbon fluid is converted to, andremains as, hydrogen sulfide during desulfurization in reactor 12.Rather, it is preferred that the fluid effluent from reactor 12(generally comprising the desulfurized hydrocarbon and hydrogen)comprises less than the amount of hydrogen sulfide, if any, in the fluidfeed charged to reactor 12 (generally comprising the sulfur-containinghydrocarbon and hydrogen). The fluid effluent from reactor 12 preferablycontains less than about 50 weight percent of the amount of sulfur inthe fluid feed charged to reactor 12, more preferably less than about 20weight percent of the amount of sulfur in the fluid feed, and mostpreferably less than five weight percent of the amount of sulfur in thefluid feed. It is preferred for the total sulfur content of the fluideffluent from reactor 12 to be less than about 50 parts per million byweight (ppmw) of the total fluid effluent, more preferably less thanabout 30 ppmw, still more preferably less than about 15 ppmw, and mostpreferably less than 10 ppmw.

When the catalyst particles are contacted with thehydrocarbon-containing stream in reactor 12 under desulfurizationconditions, it is preferred for the following reactions to take place:mild cracking of C7+ olefins, dealkylation of naphthenes, andisomerization of olefins from the alpha position to the beta positionsand isomerization of linear olefins to branched olefins. The reactionscatalyzed by the catalyst particles in reactor 12 provide an increase inthe road octane of the resulting desulfurized product versusdesulfurization with a solid particulate system employing no catalystparticles. As used herein, the terms “octane” and “road octane” shalldenote the octane of a fuel calculated by summing the research octanenumber (RON) and the motor octane number (MON) and dividing the sum ofthe MON and RON by 2.

After desulfurization in reactor 12, the desulfurized hydrocarbon fluid,preferably desulfurized cracked-gasoline, can thereafter be separatedand recovered from the fluid effluent and preferably liquified. Theliquification of such desulfurized hydrocarbon fluid can be accomplishedby any method or manner known in the art. The resulting liquified,desulfurized hydrocarbon preferably comprises less than about 50 weightpercent of the amount of sulfur in the sulfur-containing hydrocarbon(e.g., cracked-gasoline) charged to the reaction zone, more preferablyless than about 20 weight percent of the amount of sulfur in thesulfur-containing hydrocarbon, and most preferably less than five weightpercent of the amount of sulfur in the sulfur-containing hydrocarbon.The desulfurized hydrocarbon preferably comprises less than about 50ppmw sulfur, more preferably less than about 30 ppmw sulfur, still morepreferably less than about 15 ppmw sulfur, and most preferably less than10 ppmw sulfur. It is further preferred for the desulfurized hydrocarbonto have an octane number that is at least 0.01 greater than the octaneof the original sulfur-containing hydrocarbon charged to the reactionzone, more preferably 0.05 greater, still more preferably 0.1 greater,even more preferably 0.3 greater, and most preferably 0.5 greater.Another significant aspect of the present invention is that the octaneof the sulfur-containing hydrocarbon is increased with minimal liquidvolume loss. Liquid volume loss is typically attributable to theconversion of the hydrocarbon-containing (e.g., cracked-gasoline) feedto light hydrocarbons that exist in a gaseous state at standardtemperature and pressure (STP). Preferably, in order to maximizegasoline volume, at least 95 percent of the liquid volume of thehydrocarbon feed is retained, more preferably at least 97 percent, stillmore preferably at least 98 percent, and most preferably at least 99percent. Alternatively, in order to maximize light olefin production,retention of lower percentages of the liquid volume in the hydrocarboncan be preferred.

After desulfurization and octane enhancement in reactor 12, at least aportion of the solid particulate system (i.e., the sulfur-loaded sorbentparticles and the coked catalyst particles) are transported toregenerator 14 via a first transport assembly 18. In regenerator 14, thesolid particulate system is contacted with an oxygen-containingregeneration stream. The oxygen-containing regeneration streampreferably comprises at least one mole percent oxygen with the remainderbeing a gaseous diluent. More preferably, the oxygen-containingregeneration stream comprises in the range of from about one to about 50mole percent oxygen and in the range of from about 50 to about 95 molepercent nitrogen, still more preferable in the range of from about twoto about 20 mole percent oxygen and in the range of from about 70 toabout 90 mole percent nitrogen, and most preferably in the range of fromthree to 10 mole percent oxygen and in the range of from 75 to 85 molepercent nitrogen.

The regeneration conditions in regenerator 14 are sufficient to convertat least a portion of the zinc sulfide of the sulfur-loaded sorbentparticles into zinc oxide via contacting with the oxygen-containingregeneration stream, thereby removing sulfur from the sorbent particles.In addition, the regeneration conditions are sufficient to remove atleast a portion of the coke from the catalyst particles. The preferredranges for such regeneration conditions are provided below in Table 3.

TABLE 3 Regeneration Conditions Temp. Press. Superficial Vel. Range (°F.) (psig) (ft/s) Preferred 500–1500 10–250 0.5–10  More Preferred700–1200 20–150 1.0–5.0 Most Preferred 900–1100 30–75  2.0–2.5

When the sulfur-loaded solid sorbent particles are contacted with theoxygen-containing regeneration stream under the regeneration conditionsdescribed above, at least a portion of the promoter metal component isoxidized to form an oxidized promoter metal component. Preferably, inregenerator 14 the substitutional solid metal solution (M_(A)Zn_(B))and/or sulfided substitutional solid metal solution (M_(A)Zn_(B)S) ofthe sulfur-loaded sorbent is converted to a substitutional solid metaloxide solution characterized by the formula: M_(X)Zn_(Y)O, wherein M isthe promoter metal and X and Y are each numerical values in the range offrom 0.01 to about 0.99. In the above formula, it is preferred for X tobe in the range of from about 0.5 to about 0.9 and most preferably from0.6 to 0.8. It is further preferred for Y to be in the range of fromabout 0.1 to about 0.5, and most preferably from 0.2 to 0.4. Preferably,Y is equal to (1−X).

The regenerated solid particulate system exiting regenerator 14preferably comprises substantially sulfur-free sorbent particles andsubstantially coke-free catalyst particles. The substantiallysulfur-free sorbent particles can comprise zinc oxide, the oxidizedpromoter metal component (M_(X)Zn_(Y)O), the porosity enhancer (PE), andthe promoter metal-zinc aluminate (M_(Z)Zn_((1−z))Al₂O₄) in the rangesprovided below in Table 4.

TABLE 4 Components of the Regenerated Solid Sorbent Particulates ZnOM_(X)Zn_(Y)O PE M_(Z)Zn_((1–Z))Al₂O₄ Range (wt %) (wt %) (wt %) (wt %)Preferred  5–80  5–70  2–50  1–50 More Preferred 20–60 15–60  5–30  5–30Most Preferred 30–50 20–40 10–20 10–20

After regeneration in regenerator 14, the regenerated solid particulatesystem is transported to reducer 16 via a second transport assembly 20.In reducer 16, the regenerated solid particles are contacted with ahydrogen-containing reducing stream. The hydrogen-containing reducingstream preferably comprises at least about 50 mole percent hydrogen withthe remainder being cracked hydrocarbon products such as, for example,methane, ethane, and propane. More preferably, the hydrogen-containingreducing stream comprises about 70 mole percent hydrogen, and mostpreferably at least 80 mole percent hydrogen. The reducing conditions inreducer 16 are sufficient to reduce the valence of the oxidized promotermetal component of the regenerated solid sorbent particles. Thepreferred ranges for such reducing conditions are provided below inTable 5.

TABLE 5 Reducing Conditions Temp. Press. Superficial Vel. Range (° F.)(psig) (ft/s) Preferred 250–1250  25–750 0.1–4.0 More Preferred 600–1000100–400 0.2–2.0 Most Preferred 750–850  150–250 0.3–1.0

When the regenerated solid sorbent particles are contacted with thehydrogen-containing reducing stream in reducer 16 under the reducingconditions described above, at least a portion of the oxidized promotermetal component is reduced to form the reduced-valence promoter metalcomponent. Preferably, at least a substantial portion of thesubstitutional solid metal oxide solution (M_(X)Zn_(Y)O) is converted tothe reduced-valence promoter metal component (M_(A)Zn_(B)).

After the system of solid particulates has been reduced in reducer 16,it can be transported back to reactor 12 via a third transport assembly22 for recontacting with the hydrocarbon-containing fluid stream inreactor 12.

Referring again to FIG. 1, first transport assembly 18 generallycomprises a reactor pneumatic lift 24, a reactor receiver 26, and areactor lockhopper 28 fluidly disposed between reactor 12 andregenerator 14. During operation of desulfurization unit 10 thesulfur-loaded sorbent particles and coked catalyst particles arecontinuously withdrawn from reactor 12 and lifted by reactor pneumaticlift 24 from reactor 12 to reactor receiver 18. Reactor receiver 18 isfluidly coupled to reactor 12 via a reactor return line 30. The lift gasused to transport the solid particles from reactor 12 to reactorreceiver 26 is separated from the solid particles in reactor receiver 26and returned to reactor 12 via reactor return line 30. Reactorlockhopper 26 is operable to transition the solid particles from thehigh pressure hydrocarbon environment of reactor 12 and reactor receiver26 to the low pressure oxygen environment of regenerator 14. Toaccomplish this transition, reactor lockhopper 28 periodically receivesbatches of the solid particles from reactor receiver 26, isolates theparticles from reactor receiver 26 and regenerator 14, and changes thepressure and composition of the environment surrounding the particlesfrom a high pressure hydrocarbon environment to a low pressure inert(e.g., nitrogen) environment. After the environment of the solidparticles has been transitioned, as described above, the particles arebatch-wise transported from reactor lockhopper 28 to regenerator 14.Because the solid particles are continuously withdrawn from reactor 12but processed in a batch mode in reactor lockhopper 28, reactor receiver26 functions as a surge vessel wherein the solid particles continuouslywithdrawn from reactor 12 can be accumulated between transfers of theparticles from reactor receiver 26 to reactor lockhopper 28. Thus,reactor receiver 26 and reactor lockhopper 28 cooperate to transitionthe flow of the solid particles between reactor 12 and regenerator 14from a continuous mode to a batch mode.

Second transport assembly 20 generally comprises a regenerator pneumaticlift 32, a regenerator receiver 34, and a regenerator lockhopper 36fluidly disposed between regenerator 14 and reducer 16. During operationof desulfurization unit 10 the regenerated sorbent and catalystparticles are continuously withdrawn from regenerator 14 and lifted byregenerator pneumatic lift 32 from regenerator 14 to regeneratorreceiver 34. Regenerator receiver 34 is fluidly coupled to regenerator14 via a regenerator return line 38. The lift gas used to transport theregenerated particles from regenerator 14 to regenerator receiver 34 isseparated from the regenerated particles in regenerator receiver 34 andreturned to regenerator 14 via regenerator return line 38. Regeneratorlockhopper 36 is operable to transition the regenerated particles fromthe low pressure oxygen environment of regenerator 14 and regeneratorreceiver 34 to the high pressure hydrogen environment of reducer 16. Toaccomplish this transition, regenerator lockhopper 36 periodicallyreceives batches of the regenerated particles from regenerator receiver34, isolates the regenerated particles from regenerator receiver 34 andreducer 16, and changes the pressure and composition of the environmentsurrounding the regenerated particles from a low pressure oxygenenvironment to a high pressure hydrogen environment. After theenvironment of the regenerated particles has been transitioned, asdescribed above, the regenerated particles are batch-wise transportedfrom regenerator lockhopper 36 to reducer 16. Because the regeneratedsorbent and catalyst particles are continuously withdrawn fromregenerator 14 but processed in a batch mode in regenerator lockhopper36, regenerator receiver 34 functions as a surge vessel wherein theparticles continuously withdrawn from regenerator 14 can be accumulatedbetween transfers of the regenerated particles from regenerator receiver34 to regenerator lockhopper 36. Thus, regenerator receiver 34 andregenerator lockhopper 36 cooperate to transition the flow of theregenerated particles between regenerator 14 and reducer 16 from acontinuous mode to a batch mode.

The following examples are intended to be illustrative of the presentinvention and to teach one of ordinary skill in the art to make and usethe invention. These examples are not intended to limit the invention inany way.

EXAMPLES

These examples provide a comparison of desulfurization processes using abase sorbent composition only and desulfurization processes using asolid particulate system comprising both the base sorbent and variouscatalyst additive compositions. These Examples also show that the entiresolid particulate system is regenerable and that none of the solidparticulate system needs to be discarded.

Referring to FIG. 2, to generate the data set forth in Examples 1–7,below, a pilot plant 100 was used to test the effectiveness of varioussorbent/catalyst systems in desulfurizing a full range naphtha feed(1,000 ppmw sulfur and 24.8 weight percent olefins). Pilot plant 100included three reactor vessels (i.e., adsorber 102, regenerator 104, andreducer 106) and two purge vessels 108 and 110. The solid particulatesystem (e.g., sorbent or sorbent plus catalyst) was continuouslycirculated through these vessels. The solid particles were transportedvia gravity flow from purge vessel 108 to regenerator 104. The solidparticles were transported upwardly from regenerator 104 to purge vessel108 via a pneumatic lift 112 which employed nitrogen as a lift gas.

Prior to introduction into adsorber 102, the full range naphtha feed wascombined with hydrogen in a conduit 114. The feed rate of the naphthaand hydrogen to conduit 114 were 17.4 lb/hr and 16.6 l/min,respectively. The combined feed in conduit 114 was vaporized by heatingin heater 116. In adsorber 102, the vaporized feed was contacted withthe fluidized sorbent/catalyst particles at a temperature of about 775°F. to 825° F. and a pressure of about 225 psig. The adsorber 102contained a total of 3.54 pounds of the sorbent/catalyst particulates,and the circulation rate of the sorbent/catalyst particles was 2.57g/min.

The desulfurized naphtha exiting adsorber 102 via conduit 116 was cooledby chilled water in a heat exchanger 118. The cooled, desulfurizednaphtha was then conducted to a separator 120 where the hydrogen andlight gasses (C⁵⁻) were separated from the liquid desulfurized naphtha,with the desulfurized liquid naphtha product being produced via conduit122.

The sulfur loaded sorbent/catalyst particulate system was continuouslytransported from adsorber 102 to purge vessel 110 via conduit 124 at aconstant rate (i.e., 2.57 g/min). The sulfur loaded sorbent exitingadsorber 102 contained about 6 weight percent sulfur. In purge vessel110, the sulfided sorbent/catalyst particulate system was purged withnitrogen entering via conduit 126. The purged, sulfur loadedsorbent/catalyst particulate system was transported from purge vessel110 to regenerator 104 via conduit 128. In regenerator 104, thesorbent/catalyst system was contacted with a mixture of nitrogen and airentering via conduit 130. The nitrogen and air were charged toregenerator 104 at a rate of 100 l/min and 1.7 l/min, respectively. Thetemperature in regenerator 104 was maintained at about 1,025° F., andthe pressure was maintained at about 123 psig. In regenerator 104,sulfur and carbon was burned off of the sorbent/catalyst system, therebyforming a gaseous effluent containing carbon dioxide and sulfur dioxide,which exited regenerator 104 via conduit 132. The regenerated sorbentexiting regenerator 104 contained about 1 weight percent sulfur. Thus, anet sulfur loading (sulfided minus regenerated) of about 5 weightpercent was achieved in all the pilot plant tests conducted.

The regenerated sorbent/catalyst system was transported from regenerator104 to purge vessel 108 via pneumatic lift 112. In purge vessel 108, theregenerated sorbent/catalyst system was purged with nitrogen enteringpurge vessel 108 via conduit 134. The purged, regeneratedsorbent/catalyst particulate system was transported to reducer 106 viaconduit 136. In reducer 106, the regenerated sorbent/catalyst system wascontacted with a hydrogen stream entering reducer 106 via conduit 138.The hydrogen stream was charged to reducer 106 at a rate of 120 l/min.The temperature and pressure in reducer 106 were maintained at about750° F. and 225 psig, respectively. After reduction in reducer 106, thereduced sorbent was transported to adsorber 102 via conduit 140 wherethe desulfurization process was repeated.

As demonstrated in Examples 1–7, various sorbent/catalyst particulatesystems were employed in pilot plant 100 in an attempt to quantify theeffect of adding various catalysts in various amounts to the basesorbent composition. The base sorbent composition employed in thosetests was an unbound mixture of “Generation 2” sorbent particles and“Generation 3” sorbent particles. The Generation 2 and 3 sorbentparticles both had a mean particle size of about 70 microns. The basesorbent composition contained about 33 weight percent of the Generation2 sorbent particles and about 67 weight percent of the Generation 3sorbent particles. The base microspheres of the Generation 2 sorbentwere formed by spray-drying and calcining a mixture of 17.85 weightpercent expanded perlite (Sil-Kleer™ 27M, available from SilbricoCorporation, Hodgkins, Ill.), 17.25 weight percent of aluminum hydroxide(Dispal® Aluminum Powder, available from CONDEA Vista Company, Houston,Tex.), and 66 weight percent zinc oxide (available from ZincCorporation, Monaca, Pa.). The base microspheres of the Generation 3sorbent were formed by spray-drying and calcining a mixture of 21.6weight percent expanded perlite (Harborlite™ 205, available fromHarborlite Corporation, Antonio, Colo.), 21.0 weight percent aluminumhydroxide (Dispal®), and 57.2 weight percent zinc oxide (from ZincCorporation). After spray-drying and calcining, the Generation 2 and 3base microspheres were impregnated with nickel nitrate hexahydrate to atarget nickel loading of 18 weight percent nickel metal and calcined todecompose the nitrate. The actual concentration of the nickel metal onthe final Generation 2 and 3 sorbent employed in the pilot plant testswas approximately 16.5 weight percent nickel.

Inventive sorbent/catalyst particulate systems were formed by combiningvarious catalysts with the base sorbent composition described above. Thecatalysts that were combined in various proportions with the basesorbent composition included Z-CAT™ Plus (a high activity catalystcommercially available from Intercat, Sea Girt, N.J.), ISOCAT™ HP (ahigh selectivity catalyst commercially available from Intercat, SeaGirt, N.J.), and Grace Davison zeolite (a high selectivity catalystcommercially available from Grace Davison Corporation, Baltimore, Md.).The active ingredient in all three of these cracking catalysts was thezeolite H-ZSM-5. The Z-CAT™ Plus catalyst shall hereinafter be referredto as “High Activity Catalyst.” The ISOCAT™ HP catalyst shallhereinafter be referred to as “High Selectivity Catalyst#1.” The GraceDavison zeolite catalyst shall hereinafter be referred to as “HighSelectivity Catalyst#2.”

Example 1

(Comparative)

In this example, the above-described pilot plant 100 was used to conductthree comparative desulfurization runs (Runs 1–3) using only the basesorbent. Comparative Run 1 was performed at an adsorber temperature of775 ° F. Comparative Run 2 was performed at an adsorber temperature of800° F. Comparative Run 3 was performed at an adsorber temperature of825 ° F. Table 6 shows the results for Comparative Runs 1, 2, and 3.

TABLE 6 Base Sorbent Only: Run # 1 2 3 Temperature (F.) 775 800 825Product Sulfur (ppmw) 35.80 45.10 63.10 Octane Loss 0.57 0.09 −0.20 NetC3− (wt %) 0.10 0.18 0.20 Net C4− (wt %) 0.19 0.30 0.50 H2 Consumption(calc) (scf/bbl) 56.80 41.50 43.90 Delta Reid Vapor Pressure (RVP) −0.030.03 −0.10 Feed API 52.09 51.74 51.74 Feed RVP 5.35 5.24 5.24 FeedSpecific Gravity (SG) 0.77 0.77 0.77 Product API 52.72 52.32 51.98Product RVP 5.32 5.27 5.14 Product SG 0.77 0.77 0.77 Vol % Loss 0.000.00 0.36 % Vol Retained 100.00 100.00 99.64

Example 2

(5% High Activity)

In this example, three test runs (Runs 4–6) were performed with 5 weightpercent of the High Activity Catalyst being added to the base sorbentsystem. Test Runs 4, 5, and 6 were conducted at adsorber temperatures of775 ° F., 800° F., and 825° F., respectively. Table 7 shows the resultsfor Test Runs 4, 5, and 6, as well as Comparative Runs 1, 2 and 3 whichwere conducted at the same temperatures.

TABLE 7 Sorbent + 5 wt % Base Sorbent Only: Hi Activity Catalyst: Run #1 2 3 4 5 6 Temp (F.) 775 800 825 775 800 825 Prod Sulfur (ppmw) 35.8045.10 63.10 36.40 47.20 58.20 Octane Loss 0.57 0.09 −0.20 −0.69 −1.10−1.25 Delta Octane (from Base) 1.26 1.19 1.05 Net C3− (wt %) 0.10 0.180.20 1.40 1.66 2.10 Net C4− (wt %) 0.19 0.30 0.50 3.65 4.31 5.40 H2Consump (calc) (scf/bbl) 56.80 41.50 43.90 77.10 57.60 58.00 Delta RVP−0.03 0.03 −0.10 0.40 0.69 0.93 Feed API 52.09 51.74 51.74 52.52 51.9852.32 Feed RVP 5.35 5.24 5.24 5.41 5.24 5.33 Feed SG 0.77 0.77 0.77 0.770.77 0.77 Product API 52.72 52.32 51.98 54.01 54.22 55.17 Product RVP5.32 5.27 5.14 5.81 5.93 6.26 Product SG 0.77 0.77 0.77 0.76 0.76 0.76Vol % Loss 0.00 0.00 0.36 2.87 3.14 3.93 % Vol Retained 100.00 100.0099.64 97.13 96.86 96.07 % Vol Retained × Delta Octane 122.38 115.26100.87 % Vol Loss per Octane Gain Over Base 2.28 2.64 3.74 Octane GainPer % Vol Lost 0.44 0.38 0.27

Example 3

(10% High Activity)

In this Example, two Test Runs (7 and 8) were performed with 10 weightpercent of the High Activity Catalyst being added to the base sorbentsystem. Test Runs 7 and 8 were performed at adsorber temperatures of 775° F. and 825° F. Table 8 shows the results for Test Runs 7 and 8, aswell as Comparative Runs 1 and 3 which were conducted at the sametemperatures.

TABLE 8 Sorbent + 10 wt % Base Sorbent Only: Hi Activity Catalyst: Run #1 3 7 8 Temp (F.) 775 825 775 825 Prod Sulfur (ppmw) 35.80 63.10 40.0065.50 Octane Loss 0.57 −0.20 −0.76 −1.48 Delta Octane (from Base) 1.331.28 Net C3− (wt %) 0.10 0.20 1.60 2.60 Net C4− (wt %) 0.19 0.50 3.806.40 H2 Consump (calc) (scf/bbl) 56.80 43.90 71.80 45.90 Delta RVP −0.03−0.10 0.50 0.97 Feed API 52.09 51.74 52.24 52.22 Feed RVP 5.35 5.24 5.275.29 Feed SG 0.77 0.77 0.77 0.77 Product API 52.72 51.98 53.96 54.79Product RVP 5.32 5.14 5.77 6.26 Product SG 0.77 0.77 0.76 0.76 Vol %Loss 0.00 0.36 2.90 5.09 % Vol Retained 100.00 99.64 97.10 94.91 % VolRetained × Delta Octane 129.14 121.48 % Vol Loss per Octane Gain OverBase 2.18 3.98 Octane Gain Per % Vol Lost 0.46 0.25

Example 4

(15% High Activity)

In this Example, one Test Run (9) was performed with 15 weight percentof the High Activity Catalyst being added to the base sorbent system.Test Run 9 was performed at an adsorber temperature of 775° F. Table 9shows the results for Test Run 9, as well as Comparative Run 1 which wasconducted at the same temperature.

TABLE 9 Sorbent + 15 wt % Base Sorbent Only: Hi Activity Catalyst: Run #1 9 Temp (F.) 775 775 Prod Sulfur (ppmw) 35.80 49.90 Octane Loss 0.57−1.10 Delta Octane (from Base) 1.67 Net C3− (wt %) 0.10 2.40 Net C4− (wt%) 0.19 5.20 H2 Consump (calc) (scf/bbl) 56.80 72.50 Delta RVP −0.030.73 Feed API 52.09 52.34 Feed RVP 5.35 5.31 Feed SG 0.77 0.77 ProductAPI 52.72 54.44 Product RVP 5.32 6.04 Product SG 0.77 0.76 Vol % Loss0.00 4.12 % Vol Retained 100.00 95.88 % Vol Retained × Delta Octane160.12 % Vol Loss per Octane Gain Over Base 2.47 Octane Gain Per % VolLost 0.41

Example 5

(2.5% High Selectivity #1)

In this Example, three Test Runs (10, 11, and 12) were performed with2.5 weight percent of the High Selectivity Catalyst #1 being added tothe base sorbent system. Test Runs 10, 11, and 12 were performed atadsorber temperatures of 775 ° F., 800° F., and 833 ° F. Table 10 showsthe results for Test Runs 10, 11, and 12, as well as Comparative Runs 1,2, and 3 which were conducted at the same or similar temperatures.

TABLE 10 Sorbent + 2.5 wt % Base Sorbent Only: Hi Selectivity #1: Run #1 2 3 10 11 12 Temp (F.) 775 800 825 775 800 833 Prod Sulfur (ppmw)35.80 45.10 63.10 39.80 48.50 69.00 Octane Loss 0.57 0.09 −0.20 −0.08−0.54 −0.98 Delta Octane (from Base) 0.65 0.63 0.78 Net C3− (wt %) 0.100.18 0.20 0.52 0.90 1.13 Net C4− (wt %) 0.19 0.30 0.50 1.24 2.10 2.70 H2Consump (calc) (scf/bbl) 56.80 41.50 43.90 50.60 46.60 32.40 Delta RVP−0.03 0.03 −0.10 0.13 0.20 0.48 Feed API 52.09 51.74 51.74 52.34 52.6352.38 Feed RVP 5.35 5.24 5.24 5.29 5.37 5.31 Feed SG 0.77 0.77 0.77 0.770.77 0.77 Product API 52.72 52.32 51.98 53.26 53.53 54.07 Product RVP5.32 5.27 5.14 5.42 5.57 5.79 Product SG 0.77 0.77 0.77 0.77 0.76 0.76Vol % Loss 0.00 0.00 0.36 0.75 1.62 1.80 % Vol Retained 100.00 100.0099.64 99.25 98.38 98.20 % Vol Retained × Delta Octane 64.52 61.98 76.59% Vol Loss per Octane Gain Over Base 1.15 2.57 2.31 Octane Gain Per %Vol Lost 0.87 0.39 0.43

Example 6

(Various Amounts of High Selectivity #1)

In this Example, four Test Runs (12, 13, 14, and 15) were performed withvarious amounts of the High Selectivity Catalyst #1 being added to thebase sorbent system. Test Runs 12, 13, 14, and 15 employed 2.5, 5, 7.5,and 10 weight percent of the High Selectivity Catalyst #1, respectively.Test Runs 12, 13, 14, and 15 were all performed at an adsorbertemperature of 775 ° F. Table 11 shows the results for Test Runs 12, 13,14, and 15, as well as Comparative Run 1 which was conducted at the sametemperature.

TABLE 11 Base Base Sorbent + Sorbent 2.5% 5% 7.5% 10% Only: HS #1 HS #1HS #1 HS #1 Run # 1 12 13 14 15 Temp (F.) 775 775 775 775 775 ProdSulfur (ppmw) 35.80 39.80 45.50 42.90 44.90 Octane Loss 0.57 −0.08 −0.35−0.54 −0.71 Delta Octane (from Base) 0.65 0.92 1.11 1.28 Net C3− (wt %)0.10 0.52 0.68 0.88 0.85 Net C4− (wt %) 0.19 1.24 1.67 2.28 2.38 H2Consump (calc) 56.80 50.60 51.10 51.10 49.10 (scf/bbl) Delta RVP −0.030.13 0.16 0.35 0.34 Feed API 52.09 52.34 52.77 52.77 52.29 Feed RVP 5.355.29 5.39 5.39 5.29 Feed SG 0.77 0.77 0.77 0.77 0.77 Product API 52.7253.26 53.54 54.14 53.66 Product RVP 5.32 5.42 5.55 5.74 5.63 Product SG0.77 0.77 0.76 0.76 0.76 Vol % Loss 0.00 0.75 1.26 1.55 1.65 % VolRetained 100.00 99.25 98.74 98.45 98.35 % Vol Retained × Delta Octane64.52 90.84 109.28 125.89 % Vol Loss per Octane Gain 1.15 1.37 1.40 1.29Over Base Octane Gain Per % Vol Lost 0.87 0.73 0.72 0.78

Example 7

(Various Amounts of High Selectivity #2)

In this Example, three Test Runs (16, 17, and 18) were performed withvarious amounts of the High Selectivity Catalyst #2 being added to thebase sorbent system. Test Runs 16 and 17 employed 5 weight percent ofthe High Selectivity Catalyst #2, while Test Run 18 employed 10 weightpercent of the High Selectivity Catalyst #2. Test Runs 16, 17, and 18were all performed at an adsorber temperature of 775° F. Table 12 showsthe results for Test Runs 16, 17, and 18, as well as Comparative Run 1which was conducted at the same temperature.

TABLE 12 Base Sorbent + Base Sorbent 5% 5% 10% Only: HS #2 HS #2 HS #2Run # 1 16 17 18 Temp (F.) 775 775 775 775 Prod Sulfur (ppmw) 35.8043.60 43.90 49.80 Octane Loss 0.57 −0.42 −0.32 −0.68 Delta Octane (fromBase) 0.99 0.89 1.25 Net C3− (wt %) 0.10 0.84 0.78 1.30 Net C4− (wt %)0.19 2.07 1.94 3.10 H2 Consump (calc) (scf/bbl) 56.80 63.80 59.40 55.60Delta RVP −0.03 0.16 0.22 0.48 Feed API 52.09 52.50 52.25 52.23 Feed RVP5.35 5.37 5.29 5.25 Feed SG 0.77 0.77 0.77 0.77 Product API 52.72 53.4053.33 53.85 Product RVP 5.32 5.53 5.51 5.73 Product SG 0.77 0.77 0.770.76 Vol % Loss 0.00 1.59 1.37 2.24 % Vol Retained 100.00 98.41 98.6397.76 % Vol Retained × Delta Octane 97.42 87.78 122.19 % Vol Loss perOctane Gain Over Base 1.61 1.54 1.80 Octane Gain Per % Vol Lost 0.620.65 0.56

Examples 1–7 demonstrate that adding a H-ZSM-5 containing catalyst tothe base sorbent can enhance the octane number of the resultingdesulfurized product. FIG. 3 plots the change in road octane of thedesulfurized naphtha product versus the weight percent of the catalystadded to the base sorbent for the base sorbent system (i.e., sorbentonly), the sorbent/High Activity Catalyst system, the sorbent/HighSelectivity Catalyst #1 system, and the sorbent/High SelectivityCatalyst #2 system. It can be seen from FIG. 3 that in all cases theaddition of a H-ZSM-5 containing catalyst to the base sorbent improvesoctane versus the base case (i.e., sorbent only). Further, it appearsthat the High Activity Catalyst provides the most octane enhancement,with the High Selectivity Catalysts providing slightly less octaneenhancement. FIG. 3 also illustrates that the octane enhancement tendsto improve as the weight percent of the cracking catalyst in thesorbent/catalyst system increases. However, FIG. 4 shows that in allcases as the weight percent of the cracking catalyst in thesorbent/catalyst system increases the volume percent of naphtha retainedgradually decreases. FIG. 4 also illustrates that the High ActivityCatalyst provides the lowest percent volume retained, while the two HighSelectivity Catalysts provides a higher volume percent retained. Thus,the inventive sorbent/catalyst particulate system should contain anoptimum type and amount of catalyst additive so that octane issignificantly enhanced without a significant negative impact on otherproperties of the desulfurized product.

Reasonable variations, modifications, and adaptations may be made withinthe scope of this disclosure and the appended claims without departingfrom the scope of this invention.

1. A desulfurization process comprising the steps of: (a) contacting asolid particulate system with a hydrocarbon-containing fluid stream in adesulfurization zone under desulfurization conditions, wherein saidsolid particulate system comprises a sorbent and a catalyst, whereinsaid sorbent comprises zinc oxide and a promoter metal and is capable ofremoving sulfur from said hydrocarbon-containing fluid stream at saiddesulfurization conditions, wherein said catalyst comprises a zeoliteand is capable of increasing the octane of said hydrocarbon-containingfluid stream at said desulfurization conditions; (b) contacting saidsolid particulate system with an oxygen-containing regeneration streamin a regeneration zone under regeneration conditions; and (c) contactingsaid solid particulate system with a hydrogen-containing reducing streamin a reducing zone under reducing conditions, and wherein steps (a),(b), and (c) are performed simultaneously in separate desulfurization,regeneration, and reducing zones.
 2. The desulfurization process ofclaim 1, wherein said catalyst comprises a zeolite, wherein the largestring of said zeolite has at least 8 T-atoms.
 3. The desulfurizationprocess of claim 1, wherein the largest ring of said zeolite has atleast 10 T-atoms.
 4. The desulfurization process of claim 1, whereinsaid catalyst is capable of catalyzing isomerization of saidhydrocarbon-containing fluid stream at said desulfurization conditions.5. The desulfurization process of claim 1, wherein said catalyst iscapable of catalyzing cracking of said hydrocarbon-containing fluidstream at said desulfurization conditions.
 6. The desulfurizationprocess of claim 1, wherein step (b) includes removing sulfur from saidsorbent and removing coke from said catalyst.
 7. The desulfurizationprocess of claim 1, wherein step (a) includes converting at least aportion of said zinc oxide to zinc sulfide.
 8. The desulfurizationprocess of claim 7, wherein step (b) includes converting at least aportion of said zinc sulfide back to zinc oxide, wherein step (b)includes oxidizing at least a portion of said promoter metal, whereinstep (c) includes reducing at least a portion of the oxidized promotermetal.
 9. The desulfurization process of claim 1, wherein said promotermetal is selected from the group consisting of nickel, cobalt, iron,manganese, tungsten, silver, gold, copper, platinum, zinc, ruthenium,molybdenum, antimony, vanadium, iridium, chromium, and palladium. 10.The desulfurization process of claim 1, wherein said promoter metal isnickel.
 11. The desulfurization process of claim 1, wherein said sorbentfurther comprises an aluminate.
 12. The desulfurization process of claim1, wherein said sorbent further comprises perlite.
 13. Thedesulfurization process of claim 1, wherein the largest ring of saidzeolite has 10 to 12 T-atoms.
 14. The desulfurization process of claim1, wherein said zeolite has a channel dimensionality of
 3. 15. Thedesulfurization process of claim 1, wherein said catalyst comprises saidzeolite in an amount in the range of from about 5 to about 50 weightpercent.
 16. The desulfurization process of claim 1, wherein saidzeolite has a silica-alumina ratio in the range of from about 20 toabout 1,000.
 17. The desulfurization process of claim 1, wherein saidsorbent comprises said zinc oxide in an amount in the range of fromabout 20 to about 60 weight percent.
 18. The desulfurization process ofclaim 1, wherein said promoter metal is present as a substitutionalsolid metal solution with zinc.
 19. The desulfurization process of claim18, wherein said sorbent comprises said substitutional solid solution inan amount in the range of from about 20 to about 60 weight percent. 20.The desulfurization process of claim 1, wherein the weight ratio of saidsorbent to said catalyst in said solid particulate system is in therange of from about 100:1 to about4:1.
 21. The desulfurization processof claim 1, wherein said zeolite has a MFI framework type code.
 22. Thedesulfurization process of claim 1, wherein said zeolite is ZSM-5. 23.The desulfurization process of claim 22, wherein said ZSM-5 has been ionexchanged to thereby form H-ZSM-5.
 24. The desulfurization process ofclaim 1, wherein the weight ratio of said sorbent to said catalyst insaid solid particulate system is in the range of from about 40:1 toabout 5:1.
 25. The desulfurization process of claim 1, wherein saidsolid particulate system consists essentially of an unbound mixture ofdiscrete particles of said sorbent and discrete particles of saidcatalyst.
 26. The desulfurization process of claim 25, wherein saiddiscrete particles of said sorbent and said discrete particles of saidcatalyst both have a mean particle size in the range of from about 20 toabout 200 microns.
 27. The desulfurization process of claim 25, whereinsaid discrete particles of said sorbent and said discrete particles ofsaid catalyst both have a Group A Geldart characterization.
 28. Thedesulfurization process of claim 1, wherein said desulfurizationconditions include a desulfurization temperature in the range of fromabout 500° F. to about 1,000° F., wherein said regeneration conditionsinclude a regeneration temperature in the range of from about 700° F. toabout 1,200° F., and wherein said reducing conditions include a reducingtemperature in the range of from about 600° F. to about 1,000° F. 29.The desulfurization process of claim 1, wherein said desulfurizationconditions include a desulfurization temperature in the range of from700° F. to 850° F.
 30. The desulfurization process of claim 1, whereinsaid hydrocarbon-containing fluid stream is selected from the groupconsisting of cracked gasoline, gasoline, diesel fuel, and mixturesthereof, wherein said oxygen-containing regeneration stream comprises inthe range of from about 1 to about 50 mole percent oxygen, and whereinsaid hydrogen-containing reducing stream comprises at least about 50mole percent hydrogen.
 31. The desulfurization process of claim 1,wherein said hydrocarbon-containing fluid stream is cracked gasoline.32. The desulfurization process of claim 1, wherein step (a) includespassing said hydrocarbon-containing fluid stream through a firstfluidized bed of said solid particulate system, wherein step (b)includes passing said oxygen-containing regeneration stream through asecond fluidized bed of said solid particulate system, wherein step (c)includes passing said hydrogen-containing reducing stream through athird fluidized bed of said solid particulate system.
 33. Adesulfurization process comprising the steps of: (a) contacting a firstportion of a solid particulate system with a hydrocarbon-containingfluid stream in a first fluidized bed reactor under desulfurizationconditions sufficient to remove sulfur from said hydrocarbon-containingfluid stream, wherein said solid particulate system comprises aplurality of discrete sorbent particles and a plurality of discretecatalyst particles, wherein each of said sorbent particles compriseszinc oxide and a promoter metal component, wherein each of said catalystparticles comprises a zeolite capable of catalyzing isomerization andcracking of said hydrocarbon-containing fluid stream at saiddesulfurization conditions, wherein the weight ratio of said sorbentparticles to said catalyst particles is in the range of from about 100:1to about 4:1; and (b) simultaneously with step (a), contacting a secondportion of said solid particulate system with an oxygen-containingregeneration stream in a second fluidized bed reactor under regenerationconditions sufficient to remove coke film said catalyst particles,remove sulfur from said sorbent particles, and provide an oxidizedpromoter metal component.
 34. The desulfurization process of claim 33,wherein said hydrocarbon-containing fluid stream is cracked gasoline.35. The desulfurization process of claim 33, wherein saiddesulfurization conditions include a desulfurization temperature in therange of from 700° F. to 850° F.
 36. The desulfurization process ofclaim 35, wherein said regeneration conditions include a regenerationtemperature in the range of from 900° F. to 1,100° F.
 37. Thedesulfurization process of claim 33, wherein the largest ring of saidzeolite has at least 10 T-atoms.
 38. The desulfurization process ofclaim 33, wherein said zeolite has a silica-alumina ratio greater thanabout
 20. 39. The desulfurization process of claim 33, wherein saidzeolite has a MFI framework type code.
 40. The desulfurization processof claim 33, wherein said promoter metal component is a substitutionalsolid metal solution characterized by the formula M_(A)Zn_(B), wherein Mis a promoter metal and A and B are numerical values in the range offrom 0.01 to 0.99.
 41. The desulfurization process of claim 40, whereinstep (b) includes converting at least a portion of said substitutionalsolid metal solution to said oxidized promoter metal component, andwherein said oxidized promoter metal component comprises asubstitutional solid metal oxide solution characterized by the formulaM_(x)Zn_(y)O, wherein M is said promoter metal and X and Y are numericalvalues in the range of from 0.01 to 0.99.
 42. The desulfurizationprocess of claim 41, wherein M is selected from the group consisting ofnickel, cobalt, iron, manganese, tungsten, silver, gold, copper,platinum, zinc, ruthenium, molybdenum, antimony, vanadium, iridium,chromium, and palladium, A is in the range of from 0.7 to 0.97, B is inthe range of from 0.03 to 0.3, X is in the range of from 0.5 to 0.9, andY is in the range of from 0.1 to 0.5.
 43. The desulfurization process ofclaim 41, wherein M is nickel, A is in the range of from 0.85 to 0.95, Bis in the range of from 0.5 to 0.15, X is in the range of from 0.6 to0.8, and Y is in the range of from 0.2 to 0.4.
 44. The desulfurizationprocess of claim 33, further comprising the step of: (c) simultaneouslywith step (b), contacting a third portion of said solid particulatesystem with a hydrogen-containing reducing stream in a third fluidizedbed reactor under reducing conditions sufficient to reduce said oxidizedpromoter metal component.
 45. The desulfurization process of claim 1,wherein said hydrocarbon-containing fluid stream comprises greater thanabout 50 ppmw of sulfur.
 46. The desulfurization process of claim 33,wherein said hydrocarbon-containing fluid stream comprises greater thanabout 50 ppmw of sulfur.
 47. The desulfurization process of claim 1,wherein a desulfurized fluid effluent is produced from saiddesulfurization zone, wherein said desulfurized fluid effluent comprisesless weight percent of hydrogen sulfide (H₂S) than is contained in saidhydrocarbon-containing fluid stream prior to said contacting of step(a).
 48. The desulfurization process of claim 33, wherein a desulfurizedfluid effluent is produced from said first fluidized bed reactor,wherein said desulfurized fluid effluent comprises less weight percentof hydrogen sulfide (H2S) than is contained in saidhydrocarbon-containing fluid stream prior to said contacting of step(a).
 49. The desulfurization process of claim 1, wherein a desulfurizedfluid effluent is produced film said desulfurization zone, wherein saiddesulfurized fluid effluent comprises less than about 50 weight percentof the amount of sulfur in said hydrocarbon-containing fluid streamprior to said contacting of step (a).
 50. The desulfurization process ofclaim 33, wherein a desulfurized fluid effluent is produced from saidfirst fluidized bed reactor, wherein said desulfurized fluid effluentcomprises less than about 50 weight percent of the amount of sulfur insaid hydrocarbon-containing fluid stream prior to said contacting ofstep (a).
 51. The desulfurization process according to claim 1, whereinthe average particle density of said catalyst is within about 50 percentof the average particle density of said sorbent.
 52. The desulfurizationprocess according to claim 33, wherein the average density of saidcatalyst particles is within about 50 percent of the average density ofsaid sorbent particles.
 53. A desulfurization process comprising: (a)contacting a solid particulate system with a hydrocarbon-containingfluid stream in a desulfurization zone under desulfurization conditionsto thereby produce a desulfurized fluid effluent, wherein said solidparticulate system comprises a sorbent and a catalyst, wherein saidsorbent is capable of removing sulfur from said hydrocarbon-containingfluid stream at said desulfurization conditions, wherein said catalystis capable of increasing the octane of said hydrocarbon-containing fluidstream at said desulfurization conditions; and (b) contacting said solidparticulate system with an oxygen-containing regeneration stream in aregeneration zone under regeneration conditions, wherein saidhydrocarbon-containing fluid stream comprises greater than about 50 ppmwsulfur prior to said contacting of step (a).
 54. The desulfurizationprocess according to claim 53, further comprising: (c) contacting saidsolid particulate system with a hydrogen-containing reducing stream in areducing zone under reducing conditions.
 55. The desulfurization processof claim 54, wherein steps (a), (b), and (c) are performedsimultaneously in separate desulfurization, regeneration, and reducingzones.
 56. The desulfurization process according to claim 53, whereinthe average particle density of said catalyst is within about 50 percentof the average particle density of said sorbent.
 57. The desulfurizationprocess of claim 53, wherein said desulfurized fluid effluent comprisesless weight percent of hydrogen sulfide (H₂S) than is contained in saidhydrocarbon-containing fluid stream prior to said contacting of step(a).
 58. The desulfurization process of claim 53, wherein saiddesulfurized fluid effluent comprises less than about 50 weight percentof the amount of sulfur in the hydrocarbon-containing fluid stream priorto said contacting of step (a).
 59. The desulfurization process of claim53, wherein said sorbent comprises zinc oxide and a promoter metal. 60.The desulfurization process of claim 53, wherein said catalyst comprisesa zeolite.